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HOLA13 - 102
Experience with High Volume Insert PCP Technology in Cuban
Heavy Oil Fields
ALEX SANCHEZ, JAMES BARTLETTE, RUBEN MELENDEZ
Sherritt International Oil & Gas, Kudu Industries Inc.
This paper has been selected for presentation and/or publication in the proceedings for the 2013 Heavy Oil Latin America Conference & Exhibition [HOLA13]. The
authors of this material have been cleared by all interested companies/employers/clients to authorize dmg:events (Canada) inc., the congress producer, to make this
material available to the attendees of HOLA13 and other relevant industry personnel.
ABSTRACT
The application of Progressing cavity pump (PCP) technology for production of oil wells in general, continues to expand rapidly due to ongoing advances in versatility, production rate, lift capacity, durability, and economic reasons. PCPs have proven to be a successful and reliable artificial lift system for production of heavy oil fields for over 30 years.
Because of well conditions, the PCP elastomer will undergo chemical and/or mechanical degradation over time. The insert PCP was designed to significantly reduce the work-over times and lost production associated with pump replacement. Both are costs that significantly affect the profitability of E&P companies.
The paper describes the successful implementation and operation of Insert PCP systems in the extra heavy oil wells located along the northern coast of Cuba since February 2008. The field experience includes numerous tubing PCPs installations over the past 11 years, as well as the deployment of several insert PCPs. The paper also compares the pump run life, service rig work-over times and reduction of lost production achieved with the insert PCPs when compare to
conventional tubing deployed PCPs in the same application. In general, the field trial results have demonstrated that there are tremendous benefits to using this technology.
INTRODUCTION
Progressing cavity pumps (PCPs) have been available since 1931 for numerous applications in different industries to transfer, lift or transport fluids originally for the food industry. It was not until the 1960’s that the realization that this technology would be ideal for the oil industry. The use of PCPs as an artificial lift method in the oil and gas industry has continued to increase over the past 30 years. With an estimated install base of 80,000 worldwide.
The paper will describe the use of PCP systems to produce extra heavy oil from horizontal wells located along the northern coast of Cuba. The field experience contains data comparisons between the conventional PCP installations and “Insert PCP” installations.
A typical PC pump consists of two basic components: the first is called the stator – it is typically run on the end of the production tubing string and remains stationary during operation; the second is called the rotor – it is run on the end
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of a sucker rod string and rotates within the fixed stator when in operation. The elongated steel rotor is machined with a circular cross-section and a uniform helix with a prescribed eccentricity and pitch length. Rotors are normally chrome-coated to reduce friction and improve wear resistance in service. The stator cavity takes the form of a double internal helix with a pitch length that is double that of the rotor. During operation this configuration creates two series of parallel cavities within the pump which are filled by produced fluid (Matthews et al, 2007). Size of the cavities dictates the nominal displacement of the pump. The number of rotor pitches dictates the pressure rating of the pump.
In a conventional PCP the stator is installed on the bottom of the production tubing, and the rotor is installed on the bottom of the sucker rods. During the workover operation, the pump installation requires two steps. Step one is run the stator at the end of the tubing. Step two is run the rods with the rotor installed on the bottom. In order to reduce downtime, rig expenses and ensure the cost-effectiveness; a system to install and remove the pump with the rod string has been created. This eliminates the need to pull tubing to replace the pump. The entire pump assembly can be installed or removed with a rod service rig or flush-by, reducing work-over costs by 40% to 50%.
INSERT PCP SYSTEMS
The insert pump has a locking and sealing assembly attached on the top of the flush-by housing (Figure 1). It automatically locates and securely seats the pump inside the seating assembly installed in the tubing string. The drag block prevents axial and rotational movement of the pump assembly during operation.
A specially machined coupling attaches the rotor to the rod string. The coupling engages a mating profile located at the top of the insert assembly when the rod string is pulled. Unseating the pump is accomplished by simply pulling up and rotating the rod string once the coupling has engaged the profile. The flush-by housing allows the rotor to be lifted free of the stator in order to flush-by without unseating the entire pump assembly.
CUBAN OILFIELDS OVERVIEW
Oil production on the island of Cuba began in the 1880’s with the discovery of the Motembo oilfield. In the 1970’s, Cuba made a number of discoveries of heavy oil in large over-thrusted carbonate reservoirs. Sherritt
International (Cuba) Oil and Gas began operations in 1992 with initial efforts focused primarily on the recompletion of existing wells located in the Boca de Jaruco, Varadero and Pina fields (Smith et al, 2002).
The more recent field developments include the Yumuri, Puerto Escondido and Varadero reservoirs which, along with most of the other Cuban oil fields, are located along the northwestern coast of the island between Havana and Varadero as shown in Figure 2 and Figure 3. The various reservoirs produce extra heavy oil with a dead oil density ranging from 9 to 12 API○. Due to the location of the various reservoirs a short distance from the Cuban coastline, as well as their structure and main fracture orientation, they have been exploited primarily through the use of highly deviated and extended reach horizontal wells drilled from onshore locations with an average total measured depths of ~4000 m.
INSERT PCP PERFORMANCE
The first Insert PCP was installed by Sherritt in Cuba in February 2008. Subsequently, insert PCP systems were installed in 13 wells in the Varadero, Yumuri and Puerto Escondido fields. The database includes a total of 26 PCPs installed in the Cuban fields operated by Sherritt.
The Figure 6 illustrates one classic well schematic, the typical configuration used in the wells with Insert PCP systems involve 5 1/2" 17 kg/m casing as the tubing string, 5 1/2" insert PCP system and 1 1/4" sucker rods.
The observed performance characteristics of the Insert PCPs over a range of well conditions are examined further below through a detailed look at the operating history of selected wells. Summary performance data for these wells with insert PCP installations is also presented.
Case 1: YU-206RE
The first Insert installation in Cuba in February 2008 was in YU-206RE. Production from this well originally started in July 2002 and it was able to flow naturally for the first 9 months until artificial lift became necessary to produce the desired rates. In April 2003 the first conventional PCP was installed. Subsequently, eight (8) conventional PCPs were run with an average run life of 6 months. The decision was then made to test insert technology with the primary goal to reduce downtime and rig expenses.
The insert system was installed using a service rig. The approximate time to install the insert and space-out was 3 hours. The process for space-out is the same as conventional
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tubing deployed PCP with the installation of a flush by housing. A Technician returned to YU-206RE six months after operation to test the ability to unset the insert system. The insert assembly unset the first attempt with no complications. It was immediately re-set and re-started to continue producing oil to surface.
The chart in Figure 4 is showing the production history including the installation dates of the conventional and insert PCPs. The production data includes the daily oil rate, daily water rate and GOR history. The data shows that first insert pump has been successful in producing the well at the desired fluid rate. The chart also shows that the run life was 48 months, which is 8 times more than the average tubing pumps applied on the same well. The insert pump maintained the desired production rates operating at an average of 175 rpm and 70% volumetric efficiency.
Case 2: VDW-720
The first insert pump for VDW-720 was installed in January 2011. Original production from this well started in May 2009 requiring the use of a tubing deployed PCP. Before installing the first insert pump, five conventional PCPs were run in this well with a run life average of 3 months. Due to the frequency of pump replacements, the decision to run an insert system was made. A total of 4 insert pumps have been run in this well since 2011 with a run life average of 6 months. The production history of the well is summarized in Figure 5. The average pump volumetric efficiency is 60%.
As is illustrated in the well schematic (Figure 6), this well has installed with downhole pressure and temperature gauges (SRO Surface Read-Out) to help optimize the well performance. Because there is an insert system installed, it is not necessary to pull the tubing during work-overs. Therefore the gauges will remain downhole. This has a significant advantage, as it reduces rig costs, downtime, cost of new cable and risk of damaging the gauges when the completion string is removed and re-installed.
Case3: YU-201
Production from YU-201 started in June 1999 and it was able to flow naturally for three years until artificial lift became required in June 2002. From June 2002 to February 2010, 11 conventional PCPs have been installed in this well with an average run life of 8 months. In February 2010 the first insert pump was installed in this well. The overall production profile for this well is shown in Figure 7. The production data includes the daily oil rate, daily water rate and GOR history. Since then, three more insert pumps have been run with an average run life of 10 months.
The insert pump maintained the desired production rates operating at an average of 175 rpm at 75% volumetric efficiency.
COMPARISON AND ECONOMIC CONSIDERATIONS
An analysis of the general cost associated with downtime and rig time in BOE (Barrels of Oil Equivalent) between the installation of the conventional PCPs and Insert PCPs for all three cases are presented in the Table 1.
In the three cases presented in this paper a total of 11,514 BOE was estimated to be saved. Using an oil price of $65/bbl, the total estimate of savings has been ~$748,410 in the seven interventions where conventional PCPs were installed.
CONCLUSION
• The insert progressing cavity pumps technology has successfully demonstrated a substantial reduction in downtime and rig expenses. For three wells, the total estimated savings are 11,514 BOE.
• All insert PCPs have been successful in producing extra heavy oil from a number of extended reach horizontal wells in the fields in Cuba. Twenty six Insert PCPs have been run since February 2008.
• Based on the historical data, the average run life for the insert pumps have been longer than the conventional tubing deployed PCPs. The reason for this result was not studied as part of this paper.
• General limitations of the insert PCPs include handling sand and solids production. Sometimes causing difficulties in setting and un-setting. The effects of these operating parameters have not been evaluated in the Cuban wells as no solids are present in these oil producing zones.
• Another historical limitation has been the flow rates achievable. This was overcome by using 5 ½” casing as the production tubing, allowing larger volume pumps to be installed.
ACKNOWLEDGMENT
The authors would like to thank the Sherritt production personnel and workover coordinators for their interest and support in improving and implementing this new artificial lift technology.
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REFERENCES
Smith, G.E., Hurlburt, G., and Li, V.P. 2002. “Heavy Oil Carbonate: Primary Production in Cuba”. SPE Paper 79002 presented at the SPE International Thermal Operations and Heavy Oil Symposium and International Horizontal Well Technology Conference, Calgary, Alberta, Canada, 4-7 November.
Cholet H., “Progressing Cavity Pumps”, 1991. Editions Technip
Matthews, C.M., Zahacy, T.A., Alhanati, F.J.S., Skoczylas, P. and Dunn, L.J. 2007. “Progressing Cavity Pumping Systems”. Chapter 15, Vol. IV, SPE Petroleum Engineering Handbook. May.
Guerra E., Sanchez A., Matthews C. “Field Implementation Experience with Metal PCP Technology in Cuban Heavy Oil Fields” SPE Paper 120645 presented at the SPE Production and Operations Symposium held in Oklahoma City, Oklahoma, USA, 4–8 April 2009.
Dunn, L.J., Matthews, C.M., and Zahacy, T.A. 1995 “Progressing Cavity Pumping System Applications in Heavy Oil Production”. SPE Paper 30271 presented at the SPE International Heavy Oil Symposium, Calgary, Alberta, 19–21 June.
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APPENDIX
Figure 1. Insert pump assembly
Pump Setting Assembly
Installed System
Insert Assembly
Seals
Flush-byHousing
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Figure 2. Geographical Location of the Yumuri and Varadero Fields
Figure 3. Well layout in Yumuri and Puerto Escondido fields
Cuba
SeborucoYumuri
Havana
Cuba
VaraderoYumuri
Havana
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Figure 4. YU-206RE Production History
Figure 5. VDW-720RE Production History
2002 03 04 05 06 07 08 09 10 11 12 13
1
5
10
50
100
500
1000
5000
10000
Date
YU-206RE
Daily Oil ( m3/d )
Daily GOR ( scm/m3 )
Daily Water ( m3/d )
Ela
sto
me
r P
CP
Ela
sto
me
r P
CP
Ela
sto
me
r P
CP
Ela
sto
me
r P
CP
Ela
sto
me
r P
CP
Ela
sto
me
r P
CP
Ela
sto
me
r P
CP
Ela
sto
me
r P
CP
Ins
ert
Ela
sto
me
r P
CP
Ins
ert
Ela
sto
me
r P
CP
YU-206RE
2009 10 11 12 13
1
5
10
50
100
500
1000
5000
10000
Date
VDW-720RE
Daily Oil ( m3/d )
Daily GOR ( scm/m3 )
Daily Water ( m3/d )
Ela
sto
me
r P
CP
Ela
sto
me
r P
CP
Ela
sto
me
r P
CP
Ela
sto
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CP
Me
tal x
Me
tal P
CP
Ins
ert
PC
P E
las
tom
er
Ins
ert
PC
P E
las
tom
er
Ins
ert
PC
P E
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tom
er
Ins
ert
PC
P E
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tom
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VDW-720RE
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Figure 6. VDW-720RE Well Schematic
Surface Casing
Intermediate Casing
Intermediate Liner
339.7
244.5
177.8
81.10
69.90
43.16
K-55
L-80
L-80
301
1224
1087-2608
Size (OD) mm Weight (Kg/m) Grade Depth (mCF)
23
106
126
Joints
Liner 114.3 17.26 L-80 2556-4421166
301
1023
976-1495
TVD (mCF)
1482-1695
Tubing 88.9 & 114.3 13.84 & 17.26 J-55 & K-55 T.L: 9.56, 10541 & 112 N/A
VDW-720RE
October 25, 2012Date
Varadero WestField
5.80 mK.B Elevation
5.39 mK.B – C.F
1229
mKB
44
21
mC
F
Line
r Han
ger
1092
mKB
306 mKB
TD
45
69
mK
B
2613
mKB
32
01
mC
F
37
82
mC
F
41
85
mK
B
Line
r Han
ger
2560
mKB
30
93
mC
F
32
01
mC
F
38
29
mC
F
43
18
mC
F
43
51
mC
F
Cem
ent P
lug
@
2613
mKB
1
2
3
4
5
7
6
8
10
11
13
1415
16
18
20
19
12
17
9
Liner Hanger
2238 mKB
SRO @ 2465.24 mKB
N. DescriptionLength
(m)
Depth
(mCF)
PRODUCTION STRING DETAILS 2489.44
1 88.9 mm EUE bull plug w / shaved collar 0.25 2489.19
2 88.9 mm Flow nipple 1.16 2488.03
3 2 jts of 88.9 mm EUE tubing, j55 w / shaved collars 18.94 2469.09
4 88.9 mm EUE pup joint w /shaved collar and welded fins OD 140 mm 1.25 2467.84
5 88.9 mm Surface read out gauge carrier 2.60 2465.24
6 147 jts of 88.9 mm EUE tubing, j55 w / shaved collars 1394.47 1070.77
7 244.5 mm x 88.9 mm EUE Excalibre no turn tool 0.60 1070.17
8 1- jt of 88.9 mm Eue tubing J55 w / shaved collar 9.62 1060.55
9 244.5 mm x 88.9 mm Excalibre stabilizer 0.50 1060.05
10 88.9 mm Flow nipple 1.15 1058.90
11 139,7 mm LTC box x 88.9 mm EUE pin X/O 0.20 1058.70
12 5- jts of 139,7 mm LTC tubing L80 17 lb/ ft 51.19 1007.51
13 139,7 mm LTC pin x 139,7 mm buttress box X/O 0.26 1007.25
14 139,7 mm LTC tubing sub (PSN) 0.80 1006.45
15 139,7 mm LTC box x 139,7 mm buttress pin X/O 0.25 1006.20
16 139,7 mm LTC pup joint 1.25 1004.95
17 17 244.5 mm x 139,7 mm Excalibre stabilizer 0.47 1004.48
18 97- jts of 139,7 mm LTC tubing L80 17 lb/ ft 1003.81 0.67
19 139,7 mm LTC pup joint 0.46 0.21
20 244.5 mm x 139,7 mm LTC tbg hanger 0.21 0.00
Insert PCP Assembly 1046.02
21 88.9 mm EUE tubing slim hole coupling c/w bull plug 0.26 1045.76
22 88.9 mm EUE pup joint w ith slim hole coupling 1.27 1044.49
23 88.9 mm EUE perforated pup joint w / c/w tandem gauges 1.18 1043.31
24 88.9 mm EUE tag bar nipple 0.40 1042.91
25 KUDU 120K1500 IPCP - 159 s/n LGN 980 14.55 1028.36
26 114.3 mm flush by housing 6.88 1021.48
27 114.3 mm flush by housing 7.25 1014.23
28 114.3 mm flush by housing 6.10 1008.13
29 Insert Body c/w change over 0.88 1007.25
25
26
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Figure 7. YU-201 Production History
Case # Actual
Insert PCP (BOE)
Estimated Conventional PCP
(BOE)
Savings (BOE)
Savings (USD$)
@$65/bbl
YU-206 Total 1490 2514 1024 $66,560
VDW-720RE Pump 1 2231 3479 1248
Pump 2 1766 3517 1751
Pump 3 1905 3932 2027
Total 5902 10928 5026 $326,690
YU-201 Pump 1 1616 3945 2329
Pump 2 2219 3517 1298
Pump 3 1453 3290 1837
Total 5288 10752 5464 $355,160
Estimated Total Savings 11,514 $748,410
Table 1. Economic analysis between Insert PCPs & conventional PCPs
1999 2000 01 02 03 04 05 06 07 08 09 10 11 12 13
1
5
10
50
100
500
1000
5000
10000
Date
YU-201
Daily Oil ( m3/d )
Daily GOR ( scm/m3 )
Daily Water ( m3/d )
PC
P E
las
tom
er
PC
P E
las
tom
er
PC
P E
las
tom
er
PC
P E
las
tom
er
PC
P E
las
tom
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PC
P E
las
tom
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PC
P E
las
tom
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PC
P E
las
tom
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PC
P E
las
tom
er
PC
P E
las
tom
er
PC
P E
las
tom
er
Ins
ert
Ela
sto
me
r P
CP
Ins
ert
Ela
sto
me
r P
CP
Ins
ert
Ela
sto
me
r P
CP
Ins
ert
Ela
sto
me
r P
CP
YU-201
